Various different flowmeters are used in the oil and gas industry to provide information about the fluids produced by oil and gas wells. One such flowmeter is a Coriolis flowmeter. As is known to those skilled in the art, a Coriolis flowmeter includes a vibrating flowtube through which the process fluid passes and an electronic transmitter. The transmitter maintains flowtube vibration by sending a drive signal to one or more drivers and performs measurement calculations based on signals from two sensors. The physics of the device dictates that Coriolis forces act along the measurement section between sensors, resulting in a phase difference between the sinusoidal sensor signals. This phase difference is essentially proportional to the mass flow rate of the fluid passing through the measurement section. Thus, the phase difference provides a basis for a mass flow measurement of fluid flowing through the flowtube. The frequency of oscillation of the flowtube of a Coriolis meter varies with the density of the process fluid in the flowtube. The frequency value can be extracted from the sensor signals (for example by calculating the time delay between consecutive zero crossings) so that the density of the fluid can be obtained. The flowtube temperature is also monitored to enable compensation for variations in flowtube stiffness that may affect the oscillation frequency.
Coriolis meters are widely used throughout various different industries. The direct measurement of mass flow is frequently preferred over volumetric-based metering, for whereas the density and/or volume of a material may vary with temperature and/or pressure, mass remains unaffected. This is particularly important in the oil and gas industry, where energy content and hence product value is a function of mass.
A Coriolis meter measuring two parameters—mass flow and density—is theoretically able to resolve a two-phase (liquid/gas) mixture. However, unless simplifying assumptions are made, a Coriolis meter cannot on its own resolve the general three-phase oil/water/gas mixture that characterizes most oil well production. Including a third measurement of the fluid flow, such as water cut, (the proportion of water in the liquid mixture, typically scaled between 0% and 100%), enables true three-phase metering to be achieved. The term ‘Net Oil’ is used in the upstream oil and gas industry to describe the oil flow rate within a three-phase or a liquid (oil/water) stream. A common objective in the oil and gas industry is to determine the net oil produced by each well in a plurality of wells because this information can be important when making decisions affecting production from an oil and gas field and/or for optimizing production from an oil and gas field.
A conventional oil and gas well test system is shown in FIG. 1. In this well test system, one well from a plurality of wells (i.e., a cluster of N wells) is introduced into a test separator at any one time, while the remaining wells (i.e., N−1) are combined for transport to the production facility. The output of the selected well is separated in order to derive volumetric flow rates of the oil and gas being outputted from the selected well. The gas-liquid test separator flow path may be substantially different from that of the same well using the “bypass” route. Therefore, the well production in the test separator flow path may not be truly representative of its production the majority of the time when it is following the bypass route.
The present inventors have made various improvements, which will be described in detail below, applicable to the field of Coriolis flowmeters and applicable to the field of net oil and gas testing.